1. Field of the Invention
The present disclosure relates generally to modifying components of a bottomhole assembly used in oil drilling with metal-plate coatings. In particular, the disclosure relates to metal-plate coatings which comprise nanoparticles.
2. Background Art
A variety of techniques have been developed for coating machined parts to protect against oxidation, heat, wear, and corrosion. Methods for depositing such coatings include chemical and pressure vapor deposition (CVD and PVD respectively), plasma ion beam deposition, electrolytic and electroless plating, and flame spraying. The choice of which method to use for a particular application may depend on the required tolerances of the machined parts, the temperatures that the parts can withstand, the chemical composition of the parts, the desired effect of the coating, and other factors such as the size and shape of the surface to be coated. An area of particular importance in which these techniques may be applied is oil exploration, where drilling conditions can subject the various parts of the bottomhole assembly (BHA) to high temperatures, pressures, and abrasive/erosive wear.
Rotary drill bits are typically employed for drilling wells in subterranean formations. Another bit type that may be used in drilling wells are percussive bits. One type of rotary drill bit that is used is commonly referred to as a roller cone bit. Roller cone bits typically comprise a bit body having an externally threaded connection at one end, and at least one roller cone (often two or three cones are used) attached to the other end of the bit and able to rotate with respect to the bit body. Attached to the cones of the bit are a plurality of cutting elements typically arranged in rows about the surface of the cones. The cutting elements are typically tungsten carbide inserts, polycrystalline diamond compacts, or milled steel teeth.
Rotary drill bits with no moving elements on them are typically referred to as “drag” bits. Drag bits are often used to drill very hard or abrasive formations. Drag bits include those having cutting elements attached to the bit body, such as polycrystalline diamond compact insert bits, and those including abrasive material, such as diamond, impregnated into the surface of the material which forms the bit body. The latter bits are commonly referred to as “impreg” bits.
Drill bits may be used in hard, tough formations and high pressures and temperatures are frequently encountered. The total useful life of a drill bit is typically on the order of 20 to 200 hours for bits in sizes of about 6 to 28 inch diameter at depths of about 5,000 to 20,000 feet. Useful lifetimes of about 65 to 150 hours are typical. When a drill bit wears out or fails as a bore hole is being drilled, it is necessary to withdraw the drill string to replace the bit which is a very expensive and time consuming process. Prolonging the lives of drill bits minimizes the lost time in “round tripping” the drill string for replacing bits.
Replacement of a drill bit can be required for a number of reasons, including wearing out or breakage of the structure contacting the rock formation. One reason for replacing the drill bits includes failure or wear of the journal bearings on which the roller cones are mounted. The journal bearings are subjected to very high drilling loads, high hydrostatic pressures in the hole being drilled, and high temperatures due to drilling, as well as elevated temperatures in the formation being drilled. The operating temperature of the grease in the drill bit can exceed 300° F. Considerable work has been conducted over the years to produce bearing structures and employ materials that minimize wear and failure of such bearings.
Where roller cone bits are employed, the area around the seal between the journal and the roller cone can be subject to wear. This occurs because abrasives tend to get lodged in the elastomeric seal where they continually grate at the journal base and/or the roller cone.
Additionally, the cutting elements and other outer portions of any bit type are subject to constant wear with continual direct contact with hard rock formations and abrasive sands in the drilling fluids. Such wear decreases the cutting effectiveness and requires eventual bit replacement.
FIG. 1 shows one example of a conventional drilling system for drilling an earth formation. The drilling system includes a drilling rig 10 used to turn a drilling tool assembly 12 that extends downward into a wellbore 14. The drilling tool assembly 12 includes a drilling string 16, and a bottomhole assembly (BHA) 18, which is attached to the distal end of the drill string 16. The “distal end” of the drill string is the end furthest from the drilling rig.
The drill string 16 includes several joints of drill pipe 16a connected end to end through tool joints 16b. The drill string 16 is used to transmit drilling fluid (through its hollow core) and to transmit rotational power from the drill rig 10 to the BHA 18. In some cases the drill string 16 further includes additional components such as subs, pup joints, etc.
The BHA 18 includes at least a drill bit 20. Typical BHA's may also include additional components attached between the drill string 16 and the drill bit 20. Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (MWD) tools, logging-while-drilling (LWD) tools, subs, hole enlargement devices (e.g., hole openers and reamers), jars, accelerators, thrusters, downhole motors, and rotary steerable systems.
In general, drilling tool assemblies 12 may include other drilling components and accessories, such as special valves, such as kelly cocks, blowout preventers, and safety valves. Additional components included in a drilling tool assembly 12 may be considered a part of the drill string 16 or a part of the BHA 18 depending on their locations in the drilling tool assembly 12. The drill bit 20 in the BHA 18 may be any type of drill bit suitable for drilling earth formation.
In particular, the moving parts of the mud motor and portions of the drill bit experience abrasive stresses from the drilling environment. A number of prior art methods to improve the resistance of the BHA to damage have been attempted.
As one example, U.S. Pat. No. 6,371,225 discloses the use of transition metal carbide and nitrite coatings for the cutting elements (or inserts) in a rotary rock bit assembly to improve surface finish. Prior to surface finishing techniques, the hard metal coating was deposited by chemical vapor deposition (CVD) onto a tungsten carbide insert, which is tolerant of the temperatures used in the CVD technique.
In another example, U.S. Pat. No. 6,068,070 discloses the use of CVD diamond on bearing surfaces where the journal and roller cone cutter surfaces meet in a rotary drill bit. Because the temperatures of the CVD process may range from 700 to 2000° C., the bearing surfaces could not be directly coated with a CVD diamond film. A CVD diamond film was formed on a substrate, removed, and attached to the bearing surface via brazing. The brazing temperatures range from 750 to 1200° C., which precludes the use of certain materials for the base material of the journal and roller cone pieces. U.S. Pat. No. 6,105,694 discloses a similar strategy for coating cutting elements of the roller cone bit.
U.S. Pat. No. 6,450,271 discloses coatings for low adhesion to the outer portion of drill bits using plating materials, such as nickel, chromium, and copper, in conjunction with TEFLON®-like materials. Included in the methods of coating the bit are electroless plating, electrochemical plating, ion plating, and flame spraying techniques. The '271 patent also discloses the use of CVD techniques for incorporation of superabrasive materials such as diamond, polycrystalline diamond, diamond-like carbon, nanocrystalline carbon, and other carbon based coatings.
CVD and PVD techniques are typically carried out at very high temperature and are therefore not generally applicable to all BHA components that might benefit from a wear resistant coating. Accordingly, there exists a need for lower temperature methods of applying protective coatings to BHA components.